Hydrocarbons, such as oil and gas, may be recovered from various types of subsurface geological formations. The formations typically consist of a porous layer, such as limestone and sands, overlaid by a nonporous layer. Hydrocarbons cannot rise through the nonporous layer, and thus, the porous layer forms an area or reservoir in which hydrocarbons are able to collect. A well is drilled through the earth until the hydrocarbon bearing formation is reached. Hydrocarbons then are able to flow from the porous formation into the well.
In what is perhaps the most basic form of rotary drilling methods, a drill bit is attached to a series of pipe sections referred to as a drill string. The drill string is suspended from a derrick and rotated by a motor in the derrick. A drilling fluid or “mud” is pumped down the drill string, through the bit, and into the well bore. This fluid serves to lubricate the bit and carry cuttings from the drilling process back to the surface. As the drilling progresses downward, the drill string is extended by adding more pipe sections.
When the drill bit has reached the desired depth, larger diameter pipes, or casings, are placed in the well and cemented in place to prevent the sides of the borehole from caving in. Cement is introduced through a work string. As it flows out the bottom of the work string, fluids already in the well, so-called “returns,” are displaced up the annulus between the casing and the borehole and are collected at the surface.
Once the casing is cemented in place, it is perforated at the level of the oil bearing formation to create openings through which oil can enter the cased well. Production tubing, valves, and other equipment are installed in the well so that the hydrocarbons may flow in a controlled manner from the formation, into the cased well bore, and through the production tubing up to the surface for storage or transport.
This simplified drilling and completion process, however, is rarely possible in the real world. Hydrocarbon bearing formations may be quite deep or otherwise difficult to access. Thus, many wells today are drilled in stages. An initial section is drilled, cased, and cemented. Drilling then proceeds with a somewhat smaller well bore which is lined with somewhat smaller casings or “liners.” The liner is suspended from the original or “host” casing by an anchor or “hanger.” A seal also is typically established between the liner and the casing and, like the original casing, the liner is cemented in the well. That process then may be repeated to further extend the well and install additional liners. In essence, then, a modern oil well typically includes a number of tubes telescoped wholly or partially within other tubes.
Moreover, hydrocarbons are not always able to flow easily from a formation to a well. Some subsurface formations, such as sandstone, are very porous. Hydrocarbons are able to flow easily from the formation into a well. Other formations, however, such as shale rock, limestone, and coal beds, are only minimally porous. The formation may contain large quantities of hydrocarbons, but production through a conventional well may not be commercially practical because hydrocarbons flow though the formation and collect in the well at very low rates. The industry, therefore, relies on various techniques for improving the well and stimulating production from formations. In particular, various techniques are available for increasing production from formations which are relatively nonporous.
One technique involves drilling a well in a more or less horizontal direction, so that the borehole extends along a formation instead of passing through it. More of the formation is exposed to the borehole, and the average distance hydrocarbons must flow to reach the well is decreased. Another technique involves creating fractures in a formation which will allow hydrocarbons to flow more easily. Indeed, the combination of horizontal drilling and fracturing, or “frac'ing” or “fracking” as it is known in the industry, is presently the only commercially viable way of producing natural gas from the vast majority of North American gas reserves.
Fracturing a formation is accomplished by pumping fluid, most commonly water, into the well at high pressure and flow rates. The fluid is injected into the formation, fracturing it and creating flow paths to the well. Proppants, such as grains of sand, ceramic or other particulates, usually are added to the frac fluid and are carried into the fractures. The proppant serves to prevent fractures from closing when pumping is stopped.
Fracturing typically involves installing a production liner in the portion of the well bore which passes through the hydrocarbon bearing formation. The production liner may incorporate valves, typically sliding sleeve valves, which may be actuated to open ports in the valve. The valves also incorporate a plug. The plug restricts flow through the liner and diverts it through the valve ports and into the formation. Once fracturing is complete various operations will be performed to “unplug” the valve and allow fluids from the formation to enter the liner and travel to the surface.
In many wells, however, the production liner does not incorporate valves. Instead, fracturing will be accomplished by “plugging and perfing” the liner. In a “plug and perf” job, the production liner is made up from standard lengths of liner. The liner does not have any openings through its sidewalk, nor does it incorporate frac valves. It is installed in the well bore, and holes then are punched in the liner walls. The perforations typically are created by so-called “perf” guns which discharge shaped charges through the liner and, if present, adjacent cement.
A plug and perf operation can allow a well to be fractured at many different locations, but rarely, if ever, will the well be fractured all at once. The liner typically will be perforated first in a zone near the bottom of the well. Fluids then are pumped into the well to fracture the formation in the vicinity of the bottom perforations.
After the initial zone is fractured, a plug is installed in the liner at a point above the fractured zone. The liner is perforated again, this time in a second zone located above the plug. A ball then is deployed onto the plug. The ball will restrict fluids from flowing through and past the plug. When fluids are injected into the liner, therefore, they will be forced to flow out the perforations and into the second zone. After the second zone is fractured, the process is repeated until all zones in the well are fractured.
After the well has been fractured, however, plugs may interfere with installation of production equipment in the liner or may restrict the flow of production fluids upward through the liner. Thus, the plugs typically are removed from the liner after the well has been fractured. Retrievable plugs are designed to be set and then unset. Once unset, they may be removed from the well. Non-retrievable plugs are designed to be more or less permanently installed in the liner. Once installed, they must be drilled out to open up the liner. Moreover, the debris created by drilling out non-retrievable plugs must be circulated out of the well so it does not interfere with production equipment that will be installed in the liner.
Many conventional non-retrievable plugs have a common basic design built around a central support mandrel. The support mandrel is generally cylindrical and somewhat elongated. It has a central conduit extending axially through it. The support mandrel serves as a core for the plug and provides support for the other plug components. The other plug components—slips, wedges, and sealing elements—are all generally annular and are carried on and around the support mandrel in an array extending along the length of the mandrel.
More particularly, an upper set of slips is carried on the support mandrel adjacent to an upper wedge (also referred to as a “cone”). A lower set of slips is disposed adjacent to a lower wedge. The slips and wedges have mating, ramped surfaces. An annular sealing element, usually an elastomeric sealing element, is carried on the support mandrel between the upper and lower wedges. The sealing element often is provided with backup rings. The various components are carried on the support mandrel such that they may slide along the mandrel.
Such conventional frac plugs have nominal outer diameters in their “unset” position that allow them to be deployed into a liner. Once deployed, they will be set by radially expanding the slips and sealing element into contact with the liner walls. More specifically, the plugs are installed with a setting tool which may be actuated to apply opposing axial forces to the components carried around the plug support mandrel. The axial forces cause the components to slide axially along the support mandrel and squeeze together. As they are squeezed together, the ramped surfaces on the inside of the slips will cause the slips to ride up the ramped outer surface of the wedges. As they ride up the outer surface of the wedges, the slips expand radially until they contact the inner wall of the liner. The outer surfaces of the slips have teeth, serrations, and the like that enable the slips to jam and bite into the liner wall. The slips, therefore, provide the primary anchor which holds the plug in place.
Squeezing the components also will cause the elastomeric sealing element to expand radially until it seals against the liner wall. Backup rings, if present, serve to minimize axial extrusion of the elastomeric material as it is squeezed between the upper and lower wedges. The elastomeric sealing element thus can minimize or eliminate flow around the plug, i.e., between the plug and the liner wall.
The support mandrel has a ball seat at or very near the upper end of the mandrel central conduit. Once the plug is installed, and the setting tool withdrawn, fluids can flow in both directions through the central conduit. A ball may be deployed or “dropped” onto the ball seat, however, to substantially isolate the portions of the liner below the plug. The ball will restrict fluid from flowing downward through the plug.
Such designs are well known in the art and variations thereof are disclosed, for example, in U.S. Pat. No. 7,475,736 to D. Lehr et U.S. Pat. No. 7,789,137 to R. Turley et al., U.S. Pat. No. 8,047,280 to L. Tran et al., and U.S. Pat. No. 9,316,086 to D. VanLue. Plugs of that general design also are commercially available, such as Schlumberger's Diamondback composite drillable frac plug and Weatherford's TruFrac composite frac plug.
Frac plugs must resist very high hydraulic pressure—often as high as 15,000 psi or more. They also may be exposed to elevated temperatures and corrosive liquids. Thus, frac plugs traditionally were composed of relatively durable materials such as steel. Frac plugs fabricated with metal components have greater structural strength that may in turn facilitate installation of the plug. Metal components also may be less likely to loosen up and become unset, and they are more resistant to corrosion. On the other hand, the required service life of frac plugs may be relatively short, and metallic plugs are difficult to drill out.
Thus, some or all of the components of many conventional non-retrievable frac plugs now are fabricated from more easily drillable materials. Such materials include cast iron, aluminum, and other more brittle or softer metals. Other more easily drillable materials include fiberglass, carbon fiber materials, and other composite materials. Composite materials in particular are more easily drilled and, therefore, can make it easier to drill out a plug. They also can allow for less aggressive drilling and reduce the likelihood and amount of resulting damage to a liner.
It will be appreciated, however, that the central conduit of many conventional composite plugs has a relatively small diameter. Smaller diameter bores make it more likely that the plug will significantly restrict the flow of production fluids through the plug, or that it will not accommodate the passage of other tools that may be needed for remedial operations. Thus, there is a greater likelihood with small-bore plugs that the plugs will have to be drilled out.
Even with composite plugs, drill out operations can be costly and time consuming. Coil tubing drill outs typically cost $100,000.00 per day, and the process may take two to three days. Moreover, a plug and perf frac job may require the installation of dozens of plugs. Thus, even a small increase in the time required to drill an individual plug may considerably lengthen the overall cost and time required for the operation.
It also will be appreciated that composite materials lack the hardness and strength of metals such as steel, cast iron, and aluminum. Plugs fabricated from composite materials may not hold their set or seal. They may be dislodged, damaged, or leak during the fracturing process as composite materials generally lack the yield strength of metals. Composites also have much lower lateral shear strengths, and thus, are more susceptible to being blown out by a ball once hydraulic pressure above the ball is increased. Such deficiencies often are minimized by increasing the length and thickness of the plug components.
For example, making a support mandrel thicker will increase its radial yield strength and will help maintain the engagement of the slips with a liner wall. A longer support mandrel will have a proportionately higher lateral shear strength and, therefore, is better able to resist the force of a ball seated in the mandrel passageway. Increasing the size of the components, however, necessarily increases the time required to drill the plug and increased the amount of debris that must be circulated out of the well.
Additionally, while many of their components are fabricated from composites, many so-called composite plugs may still incorporate metal components which can slow down or complicate drilling out of the plug. For example, many predominantly composite plugs incorporate metallic slips which increase the time required to drill out the plug. Metal slips also can break up into relatively large pieces that may be more difficult to circulate out of a well.
Also, as noted, the elastomeric sealing element in many conventional plugs is disposed initially between the upper and lower wedges. As the wedges are squeezed together, the elastomeric sealing element is expanded radially. There also will be a tendency, however, for the elastomeric materials to extrude axially over and around the surface of the wedges. When hydraulic pressure later is applied behind the plug, it also may tend to extrude the elastomeric seal. Thus, many composite plugs incorporate metal or composite rings to back up the elastomeric seal. Such backup rings are not always effective in preventing extrusion. Metal rings especially can become entangled around the bit used to drill the plug.
The process of drilling out plugs also can be exacerbated by what is referred to as “spinning.” That is, as a plug is drilled out, the portions of the plug components remaining after most of the plug has been drilled out tend to spin with the bit. Given their relatively lower mechanical properties, spinning is a particular problem in composite plugs and can significantly increase the time required to drill out a plugs. A common solution is to provide interlocking mechanical features on the top and bottom of the plugs. Thus, if the remnant of a plug begins to spin with a bit, it will be pushed down by the bit until its lower end interlocks with the top of a plug installed lower down in the liner. That interlocking engagement will stop the plug remnant from spinning. Such interlocking geometrical features, however, can add length and material to the plug.
Finally, as various problems attendant to their installation and drilling out have been addressed, composite plugs have tended to become relatively complex. Composite materials in general can be relatively expensive, and adding to the complexity and number of components in a plug generally tends to increase the cost of fabricating and assembling the plug. Typical plug and perf jobs will require dozens of plugs, so even small increases in the cost of a plug can add up to a significant expense.
The statements in this section are intended to provide background information related to the invention disclosed and claimed herein. Such information may or may not constitute prior art. It will be appreciated from the foregoing, however, that there remains a need for new and improved composite plugs and for new and improved methods for fracking or otherwise stimulating formations using composite plugs. Such disadvantages and others inherent in the prior art are addressed by various aspects and embodiments of the subject invention.